Existing Assets - RAM Updates

RAM Studies are performed during design to predict the availability of the system over the entire life of field. However, not only does the production data change over time, but there are changes to the operating strategy and design which can impact the availability. Due to this the availability target is based on work performed many years before production started.

A local Operator requested us to perform an update to their existing RAM analysis as part of their continuous effort to capture the various changes to the asset and actual operating input. Changes were performed in steps to help define the impact of each of the changes made between the revisions.

The base-case reservoir-management strategy is water injection and produced gas re-injection. Oil is exported via a pipeline to shore. The development was drilled in two phases with a total of 19 subsea wells; 13 producers, 4 water injectors and 2 gas injectors in four drill centers. The production flow loops from Drill Center A, B & C each contain one manifold, interconnected by three sets of dual flowlines to transport the produced fluids to the topside manned Semi-submersible Floating Production System (FPS). The FPS consists of systems such as oil separation, produced water treatment, gas compression, dehydration, water injection, waste heat recovery, flare and chemical injection.

For the purpose of this study, the analysis boundary condition of the model is defined from the subsea wells through topsides facilities up to the delivery of oil via the export pipeline. The onshore terminal was not included into the model input parameters and this was modelled as a single availability number from its own study.

Below is the modeling analysis of the production system that consists of the subsea wells through topsides facilities up to the delivery of oil via the export pipeline and the addition of the onshore terminal. Noting that the overall system availability below is only a calculated average availability as the detailed interactions of the production system and SOGT have not been modeled:

The oil production efficiency is not constant over the field life. The trend in efficiency over the field life is shown below. The dips seen every two years corresponds to the planned facilities turnaround.

Approximately 6.3% absolute loss is due to planned shutdowns with the remainder consisting of unplanned failures. The topsides processing system are responsible for ~85% of the total loss in oil production, with unplanned topside failures responsible for ~45% of the total loss.

The effect of the different changes made to the model are shown below. Updating the MTTFs and the MTTRs based on Operator experience and the increase in planned maintenance were the largest contributors.

The analysis allowed the Operator to set realistic production targets going forwards, but also to understand which equipment was contributing to the unavailability – and underperforming when compared to the industry standard failure rates